Gas storage injection-production well injection-production capacity optimization method and device

Abstract

The application discloses a kind of gas storage injection-production well injection-production capacity optimization method and device, wherein the method comprises: rock core sample is carried out under alternating load condition rock sand production test, determines the limit supply capacity of reservoir;Determine the limit through capacity of string;Based on the limit supply capacity of reservoir and the limit through capacity of string, determine the injection-production capacity of gas storage injection-production well.The application can fully consider the special working condition of gas storage well, design scientific and reasonable injection-production capacity, fully exert the injection-production capacity of injection-production well, and can greatly reduce the subjective influence factors of designer, while ensuring the long-term safe operation of injection-production well under the premise of safety and reliability;The injection-production capacity of designed injection-production well is scientific and reliable, and the peak shaving capacity of gas storage can be maximized without increasing any investment.Under the premise of ensuring safety, reduce new well construction investment, improve injection-production effect of in-service well.

Description

Technical Field

[0001] This invention relates to the field of gas storage injection and production capacity optimization technology, and in particular to a method and apparatus for optimizing the injection and production capacity of gas storage injection and production wells. Background Technology

[0002] This section is intended to provide background or context for the embodiments of the invention set forth in the claims. The description herein is not an admission that it is prior art simply because it is included in this section.

[0003] Gas storage facilities play a crucial role in ensuring natural gas supply during winter, primarily by regulating the uneven distribution of natural gas supply and demand between summer and winter. This involves storing excess natural gas during the summer off-peak season and releasing it during the winter peak season. Therefore, the injection and production wells in gas storage facilities must meet the requirements of intensive injection and production; their injection and production capacity is a key factor in evaluating the efficiency of the gas storage facility. The injection and production capacity of a gas storage facility is jointly determined by the reservoir's supply capacity and the tubing's throughput capacity. Only when both the reservoir's supply capacity and the tubing's throughput capacity meet the demand can the gas storage facility reach its designed injection and production capacity. Gas storage well construction involves significant investment, necessitating intensive injection and production with as few wells as possible. Gas storage wells also pose significant safety risks; formation sand production and tubing failure can lead to major safety accidents. Highly efficient injection and production under safe conditions is the goal of gas storage facilities. Formation sand production refers to the phenomenon where, during the production process of oil, gas, and water wells, formation sand flows into the wellbore due to excessive production pressure differentials, loose cementation of sandstone oil and gas layers, etc., blocking oil and gas channels and causing well shutdowns.

[0004] Literature review reveals that existing gas storage facility injection and production capacity design methods almost entirely follow conventional gas well design methods, failing to consider the unique characteristics of gas storage facilities such as intensive injection and production, and cyclic injection and production. For example, regarding reservoir supply capacity and tubing throughput capacity, gas storage facilities often determine reservoir supply capacity using methods similar to conventional gas wells, but they do not consider special operating conditions such as intensive injection and production, thus failing to determine a reasonable reservoir supply capacity and limiting its effective utilization. Evaluating the tubing's erosion resistance is crucial for determining its maximum throughput capacity. However, currently, all gas storage wells and conventional gas wells use empirical methods to evaluate the erosion resistance of the tubing string. Many factors influence tubing erosion, and existing design methods only summarize these factors into an empirical constant, the "critical erosion coefficient," which cannot scientifically and effectively consider the influencing factors. Furthermore, the empirical constant has a large range of values, and the design results are greatly influenced by the designer's subjectivity, making it impossible to scientifically design a reasonable maximum throughput capacity. At the same time, to avoid unpredictable failure risks, designers instinctively tend to make conservative calculations, limiting the tubing string's throughput capacity. The tubing string lifespan design also does not consider the impact of different media on tubing string lifespan under cyclic injection and production conditions. Therefore, existing design methods fail to fully utilize the injection and production capacity of injection and production wells, restricting their long-term safe and efficient operation. Summary of the Invention

[0005] This invention provides a method for optimizing the injection and production capacity of injection and production wells in gas storage facilities. The method includes:

[0006] Rock sand production tests were conducted on core samples under alternating load conditions to determine the ultimate supply capacity of the reservoir.

[0007] Determine the ultimate throughput capacity of the tubing string;

[0008] The injection and production capacity of gas storage injection and production wells is determined based on the reservoir's ultimate supply capacity and the tubing's ultimate throughput capacity.

[0009] This invention provides a device for optimizing the injection and production capacity of gas storage injection and production wells, the device comprising:

[0010] The reservoir's ultimate supply capacity determination module is used to conduct rock sand production tests on core samples under alternating load conditions to determine the reservoir's ultimate supply capacity.

[0011] The tubing string limit throughput determination module is used to determine the tubing string limit throughput.

[0012] The module for determining the injection and production capacity of injection and production wells in gas storage facilities is used to determine the injection and production capacity of injection and production wells in gas storage facilities based on the reservoir's ultimate supply capacity and the tubing string's ultimate throughput capacity.

[0013] This invention also provides a computer device, including a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the computer program, it implements the above-mentioned method for optimizing the injection and production capacity of gas storage injection and production wells.

[0014] This invention also provides a computer-readable storage medium storing a computer program that, when executed by a processor, implements the steps of the above-described method for optimizing the injection and production capacity of gas storage injection and production wells.

[0015] In this embodiment of the invention, it will be applied to the design of injection and production capacity of injection and production wells in newly built gas storage facilities and newly drilled injection and production wells in existing gas storage facilities. It can optimize the design of maximum injection and production capacity, scientifically design the maximum injection and production capacity of the tubing string for safety and reasonableness, and maximize the injection and production capacity of the gas storage facility without increasing any investment. It can further reduce or avoid the additional construction costs required due to unscientific design of injection and production capacity, reduce the construction cost of gas storage facilities, improve the operating efficiency of gas storage facilities, and ensure the safe and efficient operation of gas storage facilities. Attached Figure Description

[0016] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort. In the drawings:

[0017] Figure 1 This is a flowchart of a method for optimizing the injection and production capacity of a gas storage injection and production well in an embodiment of the present invention;

[0018] Figure 2 This is a detailed schematic diagram illustrating the steps of a method for optimizing the safe and efficient injection and production capacity of a gas storage injection and production well in an embodiment of the present invention;

[0019] Figure 3 This is a flowchart illustrating a specific process for determining the ultimate supply capacity of a reservoir in an embodiment of the present invention.

[0020] Figure 4 This is a structural block diagram of a gas storage injection-production well injection-production capacity optimization device according to an embodiment of the present invention;

[0021] Figure 5 This is a schematic diagram of the data required in a gas storage well injection and production capacity optimization device according to an embodiment of the present invention. Detailed Implementation

[0022] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the embodiments of the present invention will be further described in detail below with reference to the accompanying drawings. Here, the illustrative embodiments of the present invention and their descriptions are used to explain the present invention, but are not intended to limit the present invention.

[0023] This invention proposes a method for optimizing the injection and production capacity of injection and production wells in gas storage facilities, such as... Figure 1 and Figure 2 As shown, the method includes the following steps:

[0024] Step 102: Conduct rock sand production tests under alternating load conditions to determine the reservoir's ultimate supply capacity.

[0025] The reservoir sand production pressure differential under conventional gas well production conditions is modeled using a conventional sand production model. There are many conventional sand production models, and the same model may correspond to different well types. One of these models is selected here. The conventional critical sand production pressure differential model is as follows:

[0026] ;

[0027] In the formula: —Critical sand discharge pressure difference;

[0028] —A constant, when the thick-walled cylinder has an outer diameter of 38mm and an inner diameter of 12.6mm, s=3.1;

[0029] —The breaking strength of a thick-walled cylinder can be obtained from a thick-walled cylinder compression test;

[0030] —The effective principal stress combination expression differs between horizontal and vertical wells;

[0031] —A constant, determined experimentally.

[0032] Unlike conventional gas fields, gas storage facilities operate on a cyclical injection-production basis. With each cyclical injection and production operation, the rock is subjected to alternating loads, which affect the rock strength of the reservoir. After enduring multiple cycles of alternating loads, the rock strength decreases. Studies have shown that the sand production pressure differential under injection-production conditions differs significantly from that under conventional gas well production conditions. Specifically, considering the influence of alternating loads, the ultimate sand production pressure differential is lower than that without considering alternating loads. Existing design methods do not consider the characteristics of alternating injection-production conditions in gas storage facilities; that is, traditional sand production models do not account for this influence, leading to inaccurate calculations of the critical sand production pressure differential. By comparing the changes in rock strength after conventional sand production experiments and sand production experiments under alternating load conditions, the conventional sand production model is modified by introducing a parameter that characterizes the impact of alternating loads caused by injection and production on rock strength: the rock damage coefficient D. A reservoir sand production model under injection-production conditions is established, and the ultimate sand production pressure differential of the reservoir is obtained. The formula for calculating the ultimate sand production pressure differential is as follows:

[0033] ;

[0034] In the formula: —Critical sand discharge pressure difference;

[0035] —A constant, when the thick-walled cylinder has an outer diameter of 38mm and an inner diameter of 12.6mm, s=3.1;

[0036] —The breaking strength of a thick-walled cylinder can be obtained from a thick-walled cylinder compression test;

[0037] —The effective principal stress combination expression differs between horizontal and vertical wells;

[0038] —Rock damage coefficient, dimensionless;

[0039] —A constant, determined experimentally.

[0040] The present invention conducts sand production experiments under alternating load conditions by applying axial loads of a certain frequency and magnitude to the samples based on conventional sand production experiments to simulate the influence of alternating injection and production conditions on reservoir sand production.

[0041] Based on this, the specific process for the ultimate supply capacity of the reservoir proposed in this invention is as follows: Figure 3 As shown, it includes:

[0042] Step 301: Conduct rock sand extraction tests on the core sample under alternating load conditions to determine the damage coefficient of the core sample;

[0043] Step 302: Establish a reservoir sand production model under injection and production conditions;

[0044] Step 303: Determine the ultimate supply capacity of the reservoir based on the damage coefficient of the core sample and the reservoir sand production model under the injection and production conditions.

[0045] To complete the sand production experiment under alternating load conditions, the triaxial rock testing system needs to be modified to apply periodic axial loads to the sample. The modifications to the triaxial rock testing system mainly include: 1) Improving the core sample clamp to ensure it can withstand a certain axial tensile stress after installation with the core; 2) Slightly modifying the shape of the core sample to better fit the clamp, primarily by pre-reserving a preset length at each end of the original core sample and machining grooves of preset width and depth (this is mainly an improvement in sample fixation; conventional experiments mainly involve compressive stress, requiring only simple sample fixation; the current experiment needs to simulate the tensile stress that the injection and production process may experience, so the sample needs to be machined to facilitate effective clamp control and allow it to withstand tensile stress); 3) Improving the hydraulic control system to apply periodic tensile and compressive stresses, with adjustable period and magnitude, meaning the axial load magnitude and direction are controlled by the hydraulic control system. The load frequency is determined based on the experimental cycle and injection / production cycle, while the load magnitude is determined based on the upper and lower pressure limits during the injection and production process.

[0046] After multi-cycle experiments, the damage coefficient D of the core sample can be directly measured and compared (the effect of alternating load on rock strength is calculated by integrating the strain curve with the coordinate axis). Then, by simulating injection and production parameters (mainly referring to the range and frequency of formation pressure changes during the injection and production process), the formula can be used to determine the damage coefficient D. The ultimate sand production pressure difference of the gas storage well can then be obtained.

[0047] Step 104: Conduct optimized design of the tubing under complex working conditions and determine the ultimate throughput capacity of the tubing.

[0048] The problem is divided into existing tubing and design tubing. How do we determine the ultimate throughput capacity of the tubing?

[0049] Existing tubing:

[0050] Conduct tubing throughput tests under different conditions to determine the tubing's ultimate throughput capacity; i.e., 3 below).

[0051] If it is a design column:

[0052] Determine whether to select a circulating sliding sleeve; determine the type of packer to be produced; i.e., 1) below.

[0053] Test the effect of corrosive media on injection and production tubing under alternating load conditions to determine the tubing material and thickness; i.e., 2 below).

[0054] Conduct tubing throughput tests under different conditions to determine the tubing's ultimate throughput capacity; i.e., 3 below).

[0055] Establish fatigue models of the tubing body and threads under alternating load conditions, and determine the tubing steel grade and sealing threads. (See section 4 below).

[0056] The following describes 1) to 4) in detail.

[0057] 1) Conduct optimized design of tubing structure under multiple injection and production functions.

[0058] The tubing structure of gas storage injection and production wells is similar to that of conventional gas wells, including downhole tools such as safety valves, production packers, and circulating sleeves, in addition to the tubing. However, for different injection and production characteristics of gas storage facilities, there is no clear design basis for the selection and type of downhole tools, which is greatly influenced by the subjective opinions of designers. The difficulty in selecting and type of downhole tools lies in the selection of circulating sleeves and production packers. Installing circulating sleeves facilitates later well workover operations, but their reliability and operational reliability decrease significantly with increasing well depth. Production packers are divided into retrievable packers and permanent packers, and their application in the field is rather chaotic. To facilitate the scientific design of injection and production tubing structures, gas storage wells are divided into two main categories based on depth and injection / production media. Multiple tubing structures are designed according to different injection and production functions and characteristic requirements, which can cover all gas storage wells.

[0059] (1) Wells containing corrosive media or with a depth greater than 3000m: do not select circulating sliding sleeves, and use other methods to establish circulation channels for well workover operations later; (2) Wells containing slightly corrosive media and with a depth less than 3000m: install circulating sliding sleeves to facilitate later well workover operations. Through statistical analysis of field workover data, it was found that the failure rates of retrievable packers and permanent packers in different gas storage facilities are not exactly the same. Based on the injection and production operating parameters, the production packer type with a low failure rate is preferred. Based on the statistical analysis of the overall well workover data of existing gas storage facilities, it is recommended to select permanent packers for injection and production wells and retrievable packers for reservoir monitoring wells.

[0060] 2) Conduct lifespan testing of injection and production tubing throughout its entire lifecycle.

[0061] Gas storage injection and production wells require the injection of corrosive media (CO2 and H2S) contained in the gas transmission pipeline. These corrosive media inevitably corrode the tubing. Current tubing designs largely rely on gas well material evaluation experiments, failing to reflect the impact of corrosive media on the tubing under alternating load conditions. Unlike conventional gas wells, the gas injected into storage wells comes from long-distance pipelines. This natural gas undergoes treatment before entering the pipeline and is generally dry gas, typically free of water, thus not usually causing corrosion to the tubing. Material selection must consider this difference. Injection and production operations subject the tubing to alternating loads, and research shows that alternating loads affect stress corrosion of the tubing.

[0062] Therefore, an experimental method for the effect of corrosive media on injection-production tubing under alternating load conditions was established. The material and wall thickness of the injection-production tubing were designed according to the design life requirements of the gas storage facility. The core of this experimental method is to introduce a load control system based on conventional corrosion evaluation experiments. During the experiment, alternating loads are applied to the samples to simulate the stress conditions of the injection-production tubing downhole. Specifically, the most severe corrosion environment is selected based on the injection-production conditions (many factors affect corrosion, mainly pressure and temperature; generally, pressure (the higher the partial pressure of the corrosive medium, the more severe the corrosion; temperature also has a regular effect; therefore, based on the actual field conditions, it is easy to determine the condition with the greatest impact on tubing corrosion, i.e., the most severe condition)), and the corrosion environment is simulated in a closed container. Simultaneously, based on the injection-production parameters, the axial load spectrum borne by the tubing is calculated, and the experimental load spectrum is determined based on the sample-to-tubing area ratio. Corrosion evaluation experiments are conducted to determine the sample corrosion rate. If H2S is present, the stress corrosion of the tubing should also be evaluated.

[0063] Studies have shown that alternating loads affect the corrosion rate of tubing, especially under conditions containing hydrogen sulfide, which can exacerbate tubing fracture. Therefore, corrosion evaluation experiments are conducted by simulating alternating loads, selecting appropriate materials, and optimizing tubing thickness based on corrosion rate and the designed service life of the tubing.

[0064] 3) Conduct tests on the throughput capacity of tubing under complex working conditions.

[0065] The maximum throughput capacity of a tubing string is determined by its dimensions and erosion resistance; once the string is fixed, its maximum throughput capacity is solely related to its erosion resistance. The throughput capacity is the product of the cross-sectional area within the tubing and the maximum injection / production velocity. Tubing dimensions have limited specifications, with few options and a maximum size not exceeding 7 inches (outer diameter). The maximum injection / production velocity is influenced by various factors, including tubing material, gas composition (CO2, H2S), gas-liquid ratio, internal temperature, internal pressure, and solid particles, exhibiting a wide range of variation. Based on testing requirements, experimental schemes are designed to test the throughput capacity of the tubing under different conditions. Designing experimental schemes is relatively conventional; the simplest method is to design various schemes encompassing every possibility, but this easily leads to too many schemes and an excessive workload. The optimal scheme involves optimized design, taking values ​​near the critical values ​​of each influencing factor, and designing different experimental schemes. The difference between the pipe wall thinning rate and the critical value in each experimental group is evaluated. If the difference is within ±0.05 mm / a (millimeters per year, representing the corrosion rate unit), then the experimental flow rate under that condition is the maximum injection / production flow rate for that condition. If the pipe wall thinning rate is much lower than the critical value, it proves that the experimental flow rate is lower than the maximum injection / production flow rate and can be further increased; conversely, if the difference is greater, the maximum injection / production flow rate of the tubing can be determined accordingly. Based on the injection / production flow rate, if the tubing size is known, the maximum injection / production capacity can be determined. The throughput capacity of a natural gas tubing is measured in cubic meters per day, and the injection / production flow rate is measured in meters per second. If the inner diameter of the tubing is known, the cross-sectional area of ​​the tubing can be calculated. Multiplying the injection / production flow rate by the cross-sectional area yields the flow rate, i.e., the injection / production capacity, in cubic meters per second. This is then converted to the daily flow rate to obtain the injection / production capacity. If the maximum injection / production capacity is known, the minimum tubing size can be determined.

[0066] Summary and Analysis 3), namely, conducting tubular throughput capacity tests under different operating conditions to determine the tubular's ultimate throughput capacity, including:

[0067] Determine the tube wall thinning rate under different operating conditions and tube string throughput test;

[0068] The tube wall thinning rate is compared with a preset critical value, and the ultimate throughput capacity of the tube column is determined based on the comparison result.

[0069] The tube wall thinning rate is compared with a preset critical value, and the ultimate throughput capacity of the tube string is determined based on the comparison result, including:

[0070] If the difference between the pipe wall thinning rate and the preset critical value is within the preset difference range, then the experimental flow rate under the corresponding working condition is the maximum injection-production flow rate under the corresponding working condition.

[0071] If the difference between the pipe wall thinning rate and the preset critical value is not within the preset difference range, and the pipe wall thinning rate is lower than the preset critical value, then the experimental flow rate under the corresponding working condition is lower than the maximum injection-production flow rate under the corresponding working condition, and the experimental flow rate is increased until the difference between the pipe wall thinning rate and the preset critical value is within the preset difference range.

[0072] The ultimate throughput capacity of the tubing is determined based on the maximum injection / production flow rate and tubing size.

[0073] 4) Conduct tubing strength tests under alternating injection and production conditions.

[0074] Injection and production operations subject the injection and production tubing to alternating loads. The reciprocating injection and production process causes alternating axial forces on the tubing body and threads, easily leading to fatigue failure of the tubing body and thread seal failure. Based on tubing mechanical calculations, a fatigue model of the tubing body and threads under alternating load conditions is established (this model generally refers to modeling using finite element software, a conventional technique), or fatigue tests are conducted on the tubing body and threads to simulate and evaluate tubing strength and sealing performance, and to optimize the appropriate tubing steel grade and sealing threads.

[0075] The strength verification of the tubing string can be carried out using tubing mechanics software, considering the entire life cycle of time, including tensile, compressive, internal pressure, external extrusion, and triaxial stress verification. This involves considering the impact of different operating conditions on subsequent conditions (gas storage tubing undergoes many processes from well running to production, such as replacing annular protective fluid, installing packers, gas injection, gas production, and well shut-in. During injection and production, different injection and production volumes cause different temperature and pressure changes in the tubing, leading to different stresses on the tubing, and the stress state of the tubing under one condition can be transmitted to the next). The verification is performed step-by-step. Currently, there is no professional method for verifying the thread seal of the tubing string. The finite element method can be used for verification. First, a physical model is established based on the thread dimensions. Then, actual injection and production conditions are used as boundary conditions. Finally, the contact stress of the threads under different conditions is obtained and compared with a standard (this standard refers to the contact stress standard, which differs for different threads) to determine the sealing performance of the threads.

[0076] In addition, experimental equipment can be used to conduct strength tests on the tubing body and fatigue tests on the threads. That is, based on the actual injection and production conditions, the pressure difference between the inside and outside of the tubing is calculated, and the axial load spectrum borne by the tubing is calculated. Then, the tubing is sealed, an internal pressure of the same pressure difference is applied, the two ends are fixed and a periodic axial load spectrum is applied, and a multi-cycle fatigue test is carried out to test whether the threads leak.

[0077] Step 106: Determine the injection and production capacity of the gas storage injection and production wells based on the reservoir's ultimate supply capacity and the tubing string's ultimate throughput capacity.

[0078] The injection-production capacity of an injection-production well is determined by both the reservoir's supply capacity and the throughput capacity of the injection-production tubing; the injection-production capacity is the smaller of the two. It can be designed in two main categories: existing injection-production wells and newly built injection-production wells.

[0079] 1) Existing injection and production wells

[0080] First, collect dynamic production data, design data, and experimental samples from existing wells. Dynamic production data includes: daily gas production, daily water production, daily condensate production, wellhead temperature, wellhead pressure, and gas composition. Design data includes: upper limit pressure of the gas storage tank, lower limit pressure of the gas storage tank, formation temperature, maximum injection-production capacity, maximum production pressure differential (the maximum production pressure differential is determined based on the ultimate sand production pressure differential, and is generally less than the ultimate sand production pressure differential), tubing material, tubing structure, tubing dimensions, maximum tubing throughput, and geostress parameters, etc. Experimental samples include: reservoir rock samples, sand production samples, tubing material samples, and produced fluid samples. Analyze the collected basic data to determine the experimental parameters for sand production experiments and tubing throughput tests (mainly including: temperature, pressure, water cut, sand concentration, sand particle size, tubing material, and flow rate). To facilitate technology promotion, a front-end automatic data acquisition system can be established to automatically collect and analyze the basic data. Currently, China National Petroleum Corporation (CNPC) has established a gas storage operation and management system, which allows real-time access to dynamic data such as daily gas production, daily water production, daily condensate production, wellhead temperature, and wellhead pressure. It also provides data on the upper and lower pressure limits of the gas storage facility, formation temperature, maximum designed injection and production capacity, and gas composition. Only the maximum designed production differential pressure, tubing material, tubing structure, tubing size, and maximum throughput capacity need to be viewed separately. Furthermore, reservoir stress parameters, tubing structure, material, size, and maximum throughput capacity are generally similar within the same block. Therefore, for the same block, after establishing a front-end automatic data acquisition system, only the maximum designed production differential pressure needs to be viewed separately for different wells. The front-end data acquisition system uses the upper and lower pressure limits of the gas storage facility as the pressure range for sand production tests (no conversion is needed; the upper and lower pressure limits are directly used as the highest and lowest pressures for the test). The test temperature is taken as the formation temperature. The alternating load frequency is determined considering the equipment loading cycle and the test cycle; generally, a frequency of 50Hz is sufficient. The front-end data acquisition system, based on the basic injection and production parameters and a built-in selection model (which pre-installs parameters affecting the tubing's throughput capacity; since different influencing factors have varying degrees of impact, the primary influencing factors may differ under different operating conditions), can automatically filter parameters affecting the tubing's throughput capacity and automatically sort them according to their sensitivity. It can prioritize experiments on the primary influencing parameters or study all influencing factors. Experimental parameters are based on the worst-case scenario in actual injection and production conditions. If the actual injection and production conditions are near the critical value of a parameter, an experimental point is selected on both sides of the critical value to conduct the experiment.

[0081] Secondly, experiments were conducted using the experimental equipment mentioned in step 1, according to the experimental parameters and ranges determined by the front-end data acquisition system. After the multi-cycle experiment, the new critical production pressure difference was determined by calculating the influence coefficient of alternating load on rock strength (the critical production pressure difference can be directly obtained from the experiment, or a formula can be used, i.e., a formula that corrects the conventional sand production model using the rock damage coefficient; the conventional sand production model is mentioned above). It was then determined whether the determined production pressure difference was higher than the designed production pressure difference. If it was higher, it was recommended to increase the production pressure difference on-site; if it was lower, the production pressure difference should be reduced. Simultaneously, the rock properties after the multi-cycle experiment were compared with the initial state (rock properties tested before the experiment) to determine the magnitude of property changes. Taking into account both the magnitude of the increase in production pressure difference and the magnitude of changes in reservoir properties, the maximum supply capacity of the reservoir was determined. An increase in production pressure difference determines the production output of the injection-production well; changes in reservoir properties affect the production capacity of the injection-production well, i.e., the production capacity equation changes. A simple production capacity equation including permeability parameters can be used, replacing the original permeability with the changed permeability.

[0082] Next, evaluate whether the maximum throughput capacity of the tubing string is reasonable. The existing injection-production wells have already completed the tubing string design; only step 3 of step 2 needs to be followed to evaluate the throughput capacity of the existing tubing string. According to the experimental parameters and range designed by the front-end data acquisition system, conduct the maximum throughput capacity test of the tubing string as per step 3 of step 2. This involves conducting tests under different conditions to assess whether the wall thinning rate of the tubing string is close to the critical value. Evaluate the difference between the wall thinning rate and the critical value for each set of experiments. If the difference is within ±0.05 mm / a, the experimental flow rate under that condition is the maximum injection-production flow rate under that condition. If the wall thinning rate is much lower than the critical value, it proves that the experimental flow rate is lower than the maximum injection-production flow rate and can be further improved, and vice versa. Calculate the maximum throughput capacity of the tubing string based on the determined maximum injection-production flow rate and compare it with the original designer's calculations to determine if there is potential for improving the throughput capacity. Furthermore, if conditions permit, the factors affecting the injection-production flow rate can be categorized and different conditions can be considered to create design templates; multiple design templates can be created depending on the situation. In the design template, sensitive areas are divided one by one according to the sensitivity of different factors. Combining the critical points of different influencing factors, the entire injection and production operation is divided into several regions, each corresponding to a different maximum injection and production flow rate. When designing the maximum injection and production capacity of the tubing string, the injection and production operation is compared with the calculation diagram to determine the maximum injection and production flow rate, and finally an expert system for calculating the maximum throughput capacity of the tubing string is established.

[0083] Finally, the minimum value between the reservoir supply capacity and the maximum throughput capacity of the tubing string is taken as the maximum injection-production capacity of the injection-production well. If the reservoir supply capacity is less than or equal to the throughput capacity of the tubing string, it is not advisable to replace the injection-production tubing string. If the reservoir supply capacity is much greater than the throughput capacity of the tubing string, then according to step 2, the throughput capacity of the injection-production tubing string can be improved by optimizing the design of the material, size (the size of the tubing string is limited by the wellbore size), and structure, striving to match the reservoir supply capacity.

[0084] 2) Construct new injection and production wells

[0085] For newly constructed injection-production wells, the reservoir's supply capacity should first be evaluated according to step 1, using the same evaluation method as for existing wells. Then, the structure, material, and strength of the injection-production tubing should be optimized according to steps 1, 2, and 4 in step 2. Finally, based on step 3 in step 2 and in conjunction with the reservoir's supply capacity, a reasonable tubing size should be designed (using the same design method as for existing wells) to match the reservoir's supply capacity. This leads to the design of the wellbore size, and ultimately, the design of the number of injection-production wells and the injection-production volume for the gas storage facility.

[0086] This invention also provides a device for optimizing the injection and production capacity of gas storage injection and production wells, as described in the following embodiments. Since the principle by which this device solves the problem is similar to the method for optimizing the injection and production capacity of gas storage injection and production wells, the implementation of this device can refer to the implementation of the method for optimizing the injection and production capacity of gas storage injection and production wells; repeated details will not be elaborated further.

[0087] Figure 4 This is a structural block diagram of a gas storage injection-production well injection-production capacity optimization device according to an embodiment of the present invention, such as... Figure 4 As shown, the gas storage injection-production well optimization device includes:

[0088] The reservoir's ultimate supply capacity determination module 02 is used to conduct rock sand production tests on core samples under alternating load conditions to determine the reservoir's ultimate supply capacity.

[0089] Tube string limit throughput determination module 04 is used to determine the limit throughput of the tube string;

[0090] The injection and production capacity determination module 06 for gas storage injection and production wells is used to determine the injection and production capacity of gas storage injection and production wells based on the reservoir's ultimate supply capacity and the tubing string's ultimate throughput capacity.

[0091] This gas storage injection-production capacity optimization device can be considered an expert system for optimizing injection-production capacity design based on the operation system of an oil and gas storage facility. First, the design methods for each step in this invention are standardized and programmed, with existing data built in as default data, forming a basic expert subsystem. Each subsystem allows users to modify model parameters. Then, this system interfaces with the gas storage facility operation system, automatically collecting and analyzing basic data from single wells and determining experimental plans (including parameters and the number of experimental groups). Next, experiments are conducted according to the experimental plan to determine the reservoir supply capacity and the maximum throughput capacity of the tubing string, while simultaneously deriving intermediate process parameters. Experimental data is added to the corresponding subsystems, forming a database. Finally, the system can comprehensively design the material, strength, structure, and dimensions of the tubing string and provide the maximum injection-production capacity. For new wells, the maximum injection-production capacity can be derived under existing constraints (tubing string material, dimensions, structure, etc.). Through continuous promotion and application of this expert system, more and more data will be accumulated, and the database will be continuously improved. When the database reaches a certain level, reasonable injection-production capacity can be derived without conducting laboratory experiments, using database comparison or big data comparison, such as... Figure 5 As shown.

[0092] The present invention will now be described using a gas storage facility as an example.

[0093] A gas storage facility has upper limit pressures of 15 MPa and 30 MPa, with a formation temperature of 100℃. Daily gas production is 500,000 cubic meters / day, daily water production is 2 cubic meters / day, there is no condensate oil, the produced natural gas contains 1.98% carbon dioxide, no hydrogen sulfide, and the reservoir does not produce sand. The maximum production pressure differential of a single well is approximately 3.5 MPa, and the maximum injection / production capacity of the tubing string is 1.2 million cubic meters / day at a pressure of 15 MPa. The tubing string material is 13Cr with a size of 4 1 / 2. Most of the above data can be obtained from the gas storage facility's operating system. The maximum safe injection / production capacity is now evaluated. 13Cr is a martensitic stainless steel containing 13% chromium.

[0094] Experiments were conducted using actual core samples from the formation. The lower limit of the sand production test pressure was set at 15 MPa, the upper limit at 30 MPa, the experimental temperature at 100℃, and the loading frequency at 50 Hz. Multi-cycle experiments showed that the critical production pressure could be increased to a maximum of 6.2 MPa (compared to the original design pressure differential of 3.5 MPa), and the single-well reservoir supply capacity increased from 620,000 cubic meters / day to 800,000 cubic meters / day.

[0095] Using the field tubing string as the experimental sample, the maximum throughput capacity of the tubing string was tested. Preliminary data acquisition from the front-end system indicated that the main factors affecting the throughput capacity of the reservoir, in order of importance, were: water cut, carbon dioxide partial pressure, pressure, and temperature. Tests were conducted at a pressure of 30 MPa, a carbon dioxide partial pressure of 0.6 MPa, a temperature of 100℃, and a water cut of 0.001%. Experimental results showed that even with a 50% increase in the original design flow rate, the wall thinning rate was still below the critical value of 0.076 mm / a. For conservatism, 1.5 times the original design flow rate was taken as the maximum injection-production flow rate, and the maximum throughput capacity of a single well tubing string could reach 1.52-2.28 million cubic meters per day.

[0096] Taking into account both reservoir supply capacity and tubing throughput capacity, the smaller value is taken as the peak shaving capacity of a single well. The average optimal injection and production capacity of a single well in this gas storage facility can be increased from 620,000 cubic meters / day to 800,000 cubic meters / day, and the total injection and production capacity of the entire facility can be increased by 4.2 million cubic meters / day, resulting in an annual increase of 500 million cubic meters / day in injection and production capacity.

[0097] All basic data, experimental results, and other column data from the above experiments should be entered into the expert database for later retrieval by the expert system. Figure 5 As shown.

[0098] This invention also provides a computer device, including a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the computer program, it implements the above-mentioned method for optimizing the injection and production capacity of gas storage injection and production wells.

[0099] This invention also provides a computer-readable storage medium storing a computer program that, when executed by a processor, implements the steps of the above-described method for optimizing the injection and production capacity of gas storage injection and production wells.

[0100] This invention proposes a method and apparatus for optimizing the injection and production capacity of injection and production wells in gas storage facilities. This method fully considers the unique operating conditions of gas storage wells, designs scientifically sound injection and production capacities, and maximizes the injection and production capacity of the wells. It also significantly reduces the subjective influence of designers and ensures long-term safe operation of the wells under reliable conditions. The designed injection and production capacity is scientific and reliable, maximizing the peak-shaving capacity of the gas storage facility without increasing investment. It reduces investment in new well construction and improves the injection and production efficiency of existing wells while ensuring safety.

[0101] This invention will be applied in the design of injection and production capacity for newly built gas storage injection and production wells and newly drilled injection and production wells in existing gas storage facilities. It can optimize the design of maximum injection and production capacity, and scientifically design the maximum injection and production capacity of the tubing string for safety and rationality. Without increasing any investment, it can maximize the injection and production capacity of the gas storage facility, further reduce or avoid the additional construction costs required due to unscientific design of injection and production capacity, reduce the construction cost of gas storage facilities, improve the operating efficiency of gas storage facilities, and ensure the safe and efficient operation of gas storage facilities.

[0102] Those skilled in the art will understand that embodiments of the present invention can be provided as methods, systems, or computer program products. Therefore, the present invention can take the form of a completely hardware embodiment, a completely software embodiment, or an embodiment combining software and hardware aspects. Furthermore, the present invention can take the form of a computer program product embodied on one or more computer-usable storage media (including, but not limited to, disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0103] This invention is described with reference to flowchart illustrations and / or block diagrams of methods, apparatus (systems), and computer program products according to embodiments of the invention. It will be understood that each block of the flowchart illustrations and / or block diagrams, and combinations of blocks in the flowchart illustrations and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, special-purpose computer, embedded processor, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, generate instructions for implementing the flowchart illustrations and / or block diagrams. Figure 1 One or more processes and / or boxes Figure 1 A device that provides the functions specified in one or more boxes.

[0104] These computer program instructions may also be stored in a computer-readable storage medium that can direct a computer or other programmable data processing device to function in a particular manner, such that the instructions stored in the computer-readable storage medium produce an article of manufacture including instruction means, which are implemented in a process Figure 1 One or more processes and / or boxes Figure 1 The function specified in one or more boxes.

[0105] These computer program instructions may also be loaded onto a computer or other programmable data processing equipment to cause a series of operational steps to be performed on the computer or other programmable equipment to produce a computer-implemented process, thereby providing instructions that execute on the computer or other programmable equipment for implementing the process. Figure 1 One or more processes and / or boxes Figure 1 The steps of the function specified in one or more boxes.

[0106] The specific embodiments described above further illustrate the purpose, technical solution, and beneficial effects of the present invention. It should be understood that the above descriptions are merely specific embodiments of the present invention and are not intended to limit the scope of protection of the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention.

Claims

1. A method for optimizing the injection and production capacity of injection and production wells in a gas storage facility, characterized in that, include: Rock sand production tests were conducted on core samples under alternating load conditions to determine the ultimate supply capacity of the reservoir. Determine the ultimate throughput capacity of the tubing string; Based on the reservoir's ultimate supply capacity and the tubing string's ultimate throughput capacity, the injection and production capacity of the gas storage injection and production wells is determined. Among these measures, rock sand-producing tests were conducted on core samples under alternating load conditions to determine the reservoir's ultimate supply capacity, including: The modified triaxial rock testing system was used to apply periodic axial loads to the core samples to conduct rock sand production tests and determine the ultimate supply capacity of the reservoir. The modified triaxial rock testing system includes an improved core sample holder and an improved hydraulic control system; the improved core sample holder is capable of withstanding axial tensile stress after the core sample is installed; the improved hydraulic control system is capable of applying periodic tensile and compressive stresses. Rock sand-producing tests were conducted on core samples under alternating load conditions to determine the reservoir's ultimate supply capacity, including: Rock sand extraction tests were conducted on core samples under alternating load conditions to determine the damage coefficient of the core samples; Establish a reservoir sand production model under injection and production conditions; Based on the damage coefficient of the core samples and the reservoir sand production model under the injection and production conditions, the ultimate supply capacity of the reservoir is determined. The reservoir sand production model under injection and production conditions is as follows: ； in: The critical sand discharge pressure difference; It is a constant; The breaking strength of the thick-walled cylinder; This is the expression for the effective principal stress combination; The damage amount is dimensionless. It is a constant; Determine the ultimate throughput capacity of the tubing string, including: Determine the tube wall thinning rate under different operating conditions and tube string throughput test; The tube wall thinning rate is compared with a preset critical value, and the ultimate throughput capacity of the tube string is determined based on the comparison result. The tube wall thinning rate is compared with a preset critical value, and the ultimate throughput capacity of the tube string is determined based on the comparison result, including: If the difference between the pipe wall thinning rate and the preset critical value is within the preset difference range, then the experimental flow rate under the corresponding working condition is the maximum injection-production flow rate under the corresponding working condition. If the difference between the pipe wall thinning rate and the preset critical value is not within the preset difference range, and the pipe wall thinning rate is lower than the preset critical value, then the experimental flow rate under the corresponding working condition is lower than the maximum injection-production flow rate under the corresponding working condition, and the experimental flow rate is increased until the difference between the pipe wall thinning rate and the preset critical value is within the preset difference range. The ultimate throughput capacity of the tubing is determined based on the maximum injection / production flow rate and tubing size.

2. The method for optimizing the injection and production capacity of gas storage injection and production wells as described in claim 1, characterized in that, Also includes: The shape of the core sample is improved by reserving a preset length at each end of the core sample and processing a groove with a preset width and preset depth.

3. The method for optimizing the injection and production capacity of gas storage injection and production wells as described in claim 1, characterized in that, Determine the ultimate throughput capacity of the tubing string, including: If it is an existing tubular string: Conduct tubing throughput tests under different conditions to determine the tubing's ultimate throughput capacity; If it is a design column: Determine whether to select the circulating sliding sleeve; Determine the form of the packer to be manufactured; Test the effect of corrosive media on injection and production tubing under alternating load conditions to determine the tubing material and thickness; Conduct tubing throughput tests under different conditions to determine the tubing's ultimate throughput capacity; Establish fatigue models of the tubing body and threads under alternating load conditions, and determine the tubing steel grade and sealing threads.

4. The method for optimizing the injection and production capacity of gas storage injection and production wells as described in claim 1, characterized in that, Based on the reservoir's ultimate supply capacity and the tubing's ultimate throughput capacity, the injection and production capacity of gas storage injection and production wells is determined, including: The minimum value between the reservoir's ultimate supply capacity and the tubing's ultimate throughput capacity is taken as the injection and production capacity of the gas storage injection and production well.

5. A device for optimizing the injection and production capacity of gas storage injection and production wells, characterized in that, include: The reservoir's ultimate supply capacity determination module is used to conduct rock sand production tests on core samples under alternating load conditions to determine the reservoir's ultimate supply capacity. The tubing string limit throughput determination module is used to determine the tubing string limit throughput. The module for determining the injection and production capacity of injection and production wells in gas storage facilities is used to determine the injection and production capacity of injection and production wells in gas storage facilities based on the reservoir's ultimate supply capacity and the tubing string's ultimate throughput capacity. Specifically, the reservoir's ultimate supply capacity determination module is used for: The modified triaxial rock testing system was used to apply periodic axial loads to the core samples to conduct rock sand production tests and determine the ultimate supply capacity of the reservoir. The modified triaxial rock testing system includes an improved core sample holder and an improved hydraulic control system; the improved core sample holder is capable of withstanding axial tensile stress after the core sample is installed; the improved hydraulic control system is capable of applying periodic tensile and compressive stresses. The reservoir's ultimate supply capacity determination module is specifically used for: Rock sand extraction tests were conducted on core samples under alternating load conditions to determine the damage coefficient of the core samples; Establish a reservoir sand production model under injection and production conditions; Based on the damage coefficient of the core samples and the reservoir sand production model under the injection and production conditions, the ultimate supply capacity of the reservoir is determined. The reservoir sand production model under injection and production conditions is as follows: ； in: The critical sand discharge pressure difference; It is a constant; The breaking strength of the thick-walled cylinder; This is the expression for the effective principal stress combination; The damage amount is dimensionless. It is a constant; The tubing limit throughput determination module is specifically used for: Determine the tube wall thinning rate under different operating conditions and tube string throughput test; The tube wall thinning rate is compared with a preset critical value, and the ultimate throughput capacity of the tube string is determined based on the comparison result. The tubing limit throughput determination module is specifically used for: If the difference between the pipe wall thinning rate and the preset critical value is within the preset difference range, then the experimental flow rate under the corresponding working condition is the maximum injection-production flow rate under the corresponding working condition. If the difference between the pipe wall thinning rate and the preset critical value is not within the preset difference range, and the pipe wall thinning rate is lower than the preset critical value, then the experimental flow rate under the corresponding working condition is lower than the maximum injection-production flow rate under the corresponding working condition, and the experimental flow rate is increased until the difference between the pipe wall thinning rate and the preset critical value is within the preset difference range. The ultimate throughput capacity of the tubing is determined based on the maximum injection / production flow rate and tubing size.

6. A computer device, comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that, When the processor executes the computer program, it implements the method for optimizing the injection and production capacity of gas storage injection and production wells according to any one of claims 1 to 4.

7. A computer-readable storage medium having a computer program stored thereon, characterized in that, When executed by the processor, the program implements the steps of the gas storage injection and production well optimization method according to any one of claims 1 to 4.

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